Thermal Stability of High Temperature Oil Based System Enhanced by Organophilic Clay

ABSTRACT

Compositions herein may include an oleaginous continuous phase, an aqueous discontinuous phase, a first clay comprising an organophilic smectite clay, and a second clay comprising a magnesium silicate clay. Methods herein may include circulating such fluids downhole as well as admixing a magnesium silicate dispersed clay and an organophilic smectite clay in an oleaginous base fluid.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority to U.S. Patent Application No.62/288,861, filed on Jan. 29, 2016, which is herein incorporated byreference in its entirety.

BACKGROUND

During the drilling of a wellbore, various fluids are typically used inthe well for a variety of functions. The fluids may be circulatedthrough a drill pipe and drill bit into the wellbore, and then maysubsequently flow upward through wellbore to the surface. During thiscirculation, the wellbore fluid may act to remove drill cuttings fromthe bottom of the hole to the surface, to suspend cuttings and weightingmaterial when circulation is interrupted, to control subsurfacepressures, to maintain the integrity of the wellbore until the wellsection is cased, cemented, or completed, to isolate the fluids from thesubterranean formation by providing sufficient hydrostatic pressure toprevent the ingress of formation fluids into the wellbore, to cool andlubricate the drill string and bit, and/or to maximize penetration rate.

Upon completion of drilling, a filter cake may develop on the surfacesof a wellbore from the accumulation of additives from a wellbore fluid.This filter cake may stabilize the wellbore during subsequent completionoperations such as placement of a gravel pack in the wellbore.Additionally, during completion operations, when fluid loss issuspected, a fluid loss control pill (FLCP) may be spotted into thewellbore to reduce or prevent such fluid loss by injection of othercompletion fluids behind the FLCP to a position within the wellborewhich is immediately above a portion of the formation where fluid lossis suspected. Injection of fluids into the wellbore is then stopped, andfluid loss will then move the pill toward the fluid loss location.Generally, a solids-free FLCP (i.e., with no bridging agents) may beused to minimize fluid losses while a solids-laden FLCP, for example,may be used in wells experiencing high fluid loss. In some embodiments,an invert emulsion comprising an organophilic clay and a high internalphase emulsifier can be used as FLCP's as well as in applications ofcompletion equipment/tolls installation downhole.

After completion operations have been accomplished, removal of filtercake (formed during drilling and/or completion) remaining on thesidewalls of the wellbore may be necessary. Although filter cakeformation and use of FLCP's are often used in wellbore, drilling, orcompletion operations, these barriers can present an impediment to theproduction of hydrocarbon or other fluids from the well, or to theinjection of water and/or gas, if, for example, the rock formation isstill plugged by the barrier. Because filter cake is compact, it oftenadheres strongly to the formation and may not be readily or completelyflushed out of the formation by fluid action alone.

SUMMARY

This summary is provided to introduce a selection of concepts that arefurther described below in the detailed description. This summary is notintended to identify key or essential features of the claimed subjectmatter, nor is it intended to be used as an aid in limiting the scope ofthe claimed subject matter.

In one or more aspects, embodiments disclosed herein relate to acomposition that includes an oleaginous continuous phase; an aqueousdiscontinuous phase; a first clay comprising an organophilic smectiteclay; and a second clay comprising a magnesium silicate clay.

In another aspect, embodiments disclosed herein relate to a method thatincludes circulating an invert emulsion fluid into a wellbore through aformation, the invert emulsion fluid comprising: an oleaginouscontinuous phase; an aqueous discontinuous phase; a first claycomprising an organophilic smectite clay; and a second clay comprising amagnesium silicate clay.

In yet another aspect, embodiments disclosed herein relate to a methodthat includes admixing a magnesium silicate dispersed clay and anorganophilic smectite clay in an oleaginous base fluid; shearing thedispersed clay and the organophilic clay in the oleaginous base fluid;adding an emulsifier and a halide brine to the oleaginous base fluid toform an invert emulsion fluid; and shearing the invert emulsion fluid.

Other aspects and advantages of the claimed subject matter will beapparent from the following description and the appended claims.

DETAILED DESCRIPTION

Embodiments of the present disclosure may be directed to an oil-basedwellbore fluid having improved thermal static stability and rheologicalproperties, including low end rheology, plastic viscosity, and yieldpoint. Further, such stability may be achieved with a broadercompatibility for brine chemistries and without necessitating high shearor temperatures to yield.

One or more embodiments may involve circulating an invert emulsion fluidinto a wellbore to form a filtercake on the walls thereof. The fluid maybe circulated during drilling operations or may be spotted into awellbore (as a FLCP) to form a filtercake to inhibit fluid entry fromthe well into the formation, such as during completion operations. Asused herein, a FLCP may be used to form a filtercake. In embodiments,the completion operation can include cleanout, gravel packing, or thelike, or a combination thereof. In one or more embodiments, thefiltercake can plug a screen or perforation tunnel, e.g., in acased-hole completion, until cleanout.

In an embodiment, such as in the case of high fluid loss, the FLCP maybe solids-laden and comprise particles having a mean diameter greaterthan 5 microns. In an embodiment, the FLCP comprises particles having aplurality of size gradings. Alternatively, or additionally, the FLCP cancomprise particles having a plurality of shape types selected frombeads, powders, spheres, ribbons, platelets, fibers, flakes, and so on,and combinations thereof. In other embodiments, a solids-free FLCP mayhave applications in screen running fluids, suspension fluids, and thelike.

FLCPs may be used in some embodiments to control leak-off of completionbrine after perforating and before gravel packing or frac-packing. Theyare also used in an additional or alternate embodiment to isolate thecompletion and wellbore fluid after gravel packing by spotting the pillinside the screen.

In some aspects, the FLCP may comprise a brine internal phase (e.g.,discontinuous phase) having a density of at least 1.02 kg/L (8.5 ppg(8.5 pounds per gallon)), but may be as low as 1 kg/L (8.3 ppg). A heavybrine (having a density of at least 1.5 kg/L (12.5 ppg), sometimes alsocalled a high density brine or high brine, may also be used as aninternal phase. Available water, other than brine, may also be used insome embodiments as the internal phase for the FLCP.

When used, the brine is water comprising an inorganic salt or organicsalt. Embodiments of inorganic monovalent salts include alkali metalhalides, such as sodium, potassium or cesium bromide. Embodiments ofinorganic divalent salts include calcium halides, for example, calciumchloride or calcium bromide. Zinc halides, such as zinc bromide, mayalso be used. Inorganic salt can be added to the carrier fluid in anyhydration state (e.g., anhydrous, monohydrated, dihydrated, etc.). Thecarrier brine phase may also comprise an organic salt, in embodimentssodium, potassium, or cesium formate, acetate or the like, which may beadded to the treatment fluid up to a concentration at which phaseseparation might occur, approximately 1.14 kg/L (9.5 ppg). In anembodiment, mixture of organic and inorganic salts can achieve a densityhigher than about 1.2 kg/L (10 ppg). The salt in one embodiment of theFLCP may be compatible with the wellbore fluid, or in a completion/cleanup fluid, e.g., the salt in the FLCP can be the same as the salt used inwellbore fluids.

Organophilic Clays

The present fluids may comprise at least one type of organophilic claythat assist in providing the rheological properties to the fluid,particularly suspension properties at low shear. Examples oforganophilic clays include, but are not limited to, a hectorite clay,magnesium silicate clay, organophilic sepiolite clay, and the like.

In one or more embodiments, at least one organophilic clay may be amineral clay mixture and more particularly an organophilic mineral claymixture. In one or more embodiments, the mineral clay mixture may betreated with alkyl quaternary ammonium compounds in order to render themineral clay mixture hydrophobic; such clays may also be termedorganophilic. In one or more embodiments, the mineral clay mixturescomprise: a mineral clay (a) comprising 50 to 95 wt. %, based on theweight of the mineral clay mixture, or 60 to 95 wt. %, or 70 to 90 wt. %of a mineral clay selected from the group including sepiolite,palygorskite and mixtures of sepiolite and palygorskite (or othermagnesium silicate-based clays alone or in combination with sepioliteand/or palygorskite); and a mineral clay (b) comprising the balance byweight of the mineral clay mixture, of a smectite. In one or moreembodiments, the smectite may be a natural or synthetic clay mineralselected from the group including hectorite, montmorillonite, bentonite,beidelite, saponite, stevensite and mixtures thereof. The Garamite lineof products available from BYK Additives, (Gonzalez, Tex.) arerepresentative examples of mixed mineral clay products. Garamite®, awet-processed organoclay, may comprise components such as anorganophilic sepiolite and a quaternary amine surfactant, and may act asa suspending agent for wellbore fluids. Due to its unique rheologicalprofile, such magnesium silicate-based suspending agent may increase thelow shear viscosity (i.e., suspension) of oil-based wellbore fluidswhile having minimal impact on high shear viscosity as compared to atraditional organically modified clay which may be used primarily as aviscosifier. The magnesium silicate-based suspending agent may providelow shear viscosity, aka suspension, in wellbore fluids where atraditional organically modified clay is used as a primary viscosifier.In one or more embodiments, the clay minerals may be wet-processed, suchas by first dispersing and/or allowing to swell in the presence of waterto remove all impurities, to yield complete minerals with homogenoussurface to allow exchange with surfactant(s). There may be minimalstacking or rebundling of such processed clay minerals within the claymixture used herein, which may include a mix of hydrophobic rods orplate minerals, and thus, allows for easy dispersion. Further, magnesiumsilicate clays, such as Garamite®, are relatively easily disperableclays and may not require any or significant high shear or hightemperature to yield.

Both sepiolite and palygorskite are included in the broad grouping ofphyllosilicates, or sheet silicates, because they contain a continuoustwo-dimensional tetrahedral sheet of composition T₂O₅ (T=Si, Al, Be, . .. ) but they differ from other layer silicates in lacking continuousoctahedral sheets. Thus, they may have properties that differ from otherlayer silicates and the mineral clay mixture described above may alsohave differing properties as a result of their presence in theadmixture. For example, when compared on a mass basis, the same mass ofthe mineral clay mixture may have a larger bulk volume than conventionalsuspending agents that use only smectite type layer silicates. As aresult of the increased bulk volume, when using the mineral clay mixtureit may be possible to use less suspending agent than is conventionallyused to achieve the fluid properties to suspend hydratable polymertherein. The use of less suspending agent may also facilitate easiermixing of the mineral clay mixture into the carrier fluid.

In one or more embodiments, the alkyl quaternary ammonium salts employedfor treating the mineral clay mixtures comprise alkyl quaternaryammonium salts containing the same or different straight and/orbranched-chain saturated and/or unsaturated alkyl groups of 1 to 22carbon atoms and the salt moiety is selected from the group includingchloride, bromide, methylsulfate, nitrate, hydroxide, acetate, phosphateand mixtures thereof. In one or more embodiments, the alkyl quaternaryammonium salts are dimethyl di(hydrogenated tallow) ammonium chloride,methylbenzyl di(hydrogenated tallow) ammonium chloride, dimethylbenzylhydrogenated tallow ammonium chloride, dimethyl hydrogenated tallow-2ethylhexylammonium methylsulfate and mixtures of two or more of theabove. It is also envisioned that other fatty acid based quaternaryammonium salts may be used

As mentioned, the mineral clay mixtures may include, in addition to themagnesium silicate based clay another organophilic clay that is asmectite. In one or more particular embodiments, the additionalorganophilic clay used herein may be a hectorite clay. An example of ahectorite clay may be VERSAGEL HT™ available from MI-SWACO (Houston,Tex.). Such clay may be a viscosifier used to increase carrying capacityand suspension properties, provide support for weighting materials,improve cuttings removal in wellbore fluids, and aid in filtercakeformation and filtration control. Further, while the above descriptiondescribes a mixture that includes sepiolite, palygorskite, othermagnesium silicate clays, or mixtures thereof in an amount that is atleast 50% by weight of the clay mixture (with the balance being asmectite), it is also understood that in one or more embodiments, suchclay mixture may be combined with an additional quantity of a smectiteclay, such that in the wellbore fluid formulation, the smectite ispresent at a ratio that is greater than 1:1 (smectite:magnesiumsilicate). In such instance, the organophilic surface modificationpresent on the smectite clay may be the same or different from theorganophilic surface modification present on the magnesium silicate. Itis also envisioned that within the wellbore fluid formulation, there maybe smectites having two distinct organophilic surface modificationsthereon. When the entire wellbore fluid formulation is considered, thesepiolite, palygorskite, other magnesium silicate clays, or mixturesthereof may be present, relative to the total amount of organophilicclay in an amount that ranges from a lower limit of any of 20, 25, 30,35, 40, 45 or 50 percent by weight and an upper limit of any of 35, 40,45, 50, 60, 70, 80 or 90 percent by weight, where any lower limit can beused in combination with any upper limit. In particular embodiments, thesepiolite, palygorskite, other magnesium silicate clays, or mixturesthereof may be present, relative to the total amount of organophilicclay in a wellbore fluid formulation in an amount that ranges from 30 to45 percent by weight.

As seen below, magnesium silicate clay and hectorite clay, such as incombination, may enhance the thermal stability of invert emulsions, suchas FLCPs, which comprise high internal phase emulsifiers in zinc-basedbrines. Without such organophilic clays, typical high internal phaseemulsifiers may provide limited stability for invert emulsions in zincbromide brines, such as for 2 days at 375° F. As shown below, additionof organophilic clays, such as hectorite clay, magnesium silicate clay,organophilic sepiolite clay, or a combination thereof, may provideenhanced stability of such invert emulsion fluids for at least 5 days at375° F. Further, addition of the previously mentioned organophilic claysmay increase the low end rheology and reduce plastic viscosity and yieldpoint of the invert emulsions.

Emulsifier

One of the components of wellbore fluids of the present disclosure is anemulsifier that enhances the functional capability of the entire fluidsystem, such as, the stability or oil wetting in high temperature highpressure (HTHP) conditions. Furthermore, the combination of suchemulsifiers with organophilic clays results in improved thermalstability and rheological properties of the fluid. The role of thethermally stable fluid is to maintain viscosity and fluid lossproperties in the wellbore fluid, as it becomes exposed to increasedtemperatures encountered during drilling and production of oil and gasfrom subterranean formations.

Such emulsifiers may comprise paraffins, fatty-acids, amine-basedcomponents, amidoamines, polyolefin amides, soaps of fatty acids,polyamides, polyamines, polyolefin amides, polyolefin amidealkeneamines, alkoxylated ether acids (such as an alkoxylated fattyalcohol terminated with a carboxylic acid), oleate esters, such assorbitan monoleate, sorbitan dioleate, imidazoline derivatives oralcohol derivatives and combinations or derivatives of the above or thelike. Blends of these materials as well as other emulsifiers can be usedfor this application. Examples of such emulsifiers, such as a highinternal phase emulsifier, may be SUREMUL PLUS™ available from MI-SWACO(Houston, Tex.). In particular embodiments, the organophilic claysmixtures of the present disclosure may be used in an invert emulsionfluid stabilized by an emulsifier formed from a fatty acid (one or moreof a C10-C24 fatty acid, for example, which may include linear and/orbranched, and saturated and/or unsaturated fatty acids) reacted with oneor more ethyleneamines (e.g., ethylenediamine, diethylenetriamine,triethylenetetraamine, tetraethylenepentaamine) to produce one or moreof amides, polyamides, and/or amidoamines, depending, for example, onthe mole ratio of the polyamine to the fatty acid. In one or moreembodiments, the emulsifier may be a dimer poly-carboxylic C12 to C22fatty acid, trimer poly-carboxylic C12 to C22 fatty acid, tetramerpoly-carboxylic C12 to C22 fatty acid, mixtures of these acids, or apolyamide wherein the polyamide is the condensation reaction product ofa C12-C22 fatty acid and a polyamine selected from the group consistingof diethylenetriamine, triethylenetetramine; and tetraethylenepentamine.

In one or more embodiments, the organophilic clays mixtures of thepresent disclosure may be used in an invert emulsion fluid stabilized byan emulsifier formed from a polyolefin (such as having a terminal vinylgroup, such as polyisobutylene), a carboxylic acid (particularly a di-or poly-carboxylic acid or anhydride thereof), and an alkeneamine(including ethylenediamine, diethylenetriamine, triethylenetetraamine,tetraethylenepentaamine, as well as propyleneamine variants thereof). Itis also understood that the polyolefin may be first functionalized withthe acid (such as to form polyisobutylene succinic anhydride) prior toreaction with the alkeneamine to form an amide.

In one embodiment, the wellbore fluids of the disclosure may furthercontain other additives and chemicals that are known to be commonly usedin oilfield applications by those skilled in the art. A variety ofadditives can be included in the oil based wellbore fluid of thisdisclosure for the formation of a thin, low permeability filter cakewhich seals pores and other openings in the formations which arepenetrated by the bit. Such additives may include thinners, weightingmaterial, wetting agents, surfactants, shale inhibitors, pH buffers,etc.

Wellbore fluids of the present disclosure may contain other materials tocomprise complete wellbore fluids. Such other materials optionally mayinclude, for example: additives to reduce or control low temperaturerheology or to provide thinning, additives for enhancing viscosity,additives for high temperature high pressure control and emulsionstability. As typically with wellbore fluids, the formulations of thefluids of the present disclosure vary with the particular requirementsof the subterranean formation.

A characteristic of the wellbore fluid which is controlled by theorganophilic clay of this disclosure is its viscosity. The viscosity ofwellbore fluids is very difficult to control because of the adverseconditions under which wellbore fluids are used, as well as theexcessively elevated temperatures to which they will be exposed. In thisregard, during the drilling of certain deep wells, i.e., greater than15,000 feet, it is common to be exposed to temperatures at which thermaldecomposition of certain wellbore fluid additives occurs. Thesetemperatures can easily cause a severe change in the viscosity of thefluid and thus adversely affect the flow characteristics of the mud andadversely affect the overall drilling operation. Such viscositymodification at these temperatures is not acceptable in typical wellborefluids. Additionally, certain geographic regions have excessivegeothermal activity resulting in extremely high temperatures. The effecton wellbore fluids at these geothermally elevated temperatures may besimilar to the effect of elevated temperatures in deep wells.

The fluids may be formulated or mixed according to various procedures,as generally known for producing wellbore fluids. In some embodiments,the organophilic clay may be pre-dispersed, such as in oil or water andallowed to swell or yield, prior to addition to other components.Shearing of the composition, such as for at least 25 minutes, may occurafter dispersion of the clay. At least one emulsifier and aqueous fluid,such as brine (e.g., halide brine, zinc brine), may be added to thedispersed clay, followed by additional shearing. The process offormulating the wellbore fluid may continue with the addition ofportions of aqueous fluid (e.g., brine), followed by shearing. Inparticular embodiments, the organophilic clay may first be dispersedinto an oleaginous fluid, followed by addition of an emulsifier andaqueous fluid.

Upon mixing, the fluids, such as FLCPs, of the present embodiments maybe used in wellbore related operations, such as drilling, completion,workover, production operations, or the like. Wellbore techniques areknown to persons skilled in the art and involve pumping a wellbore fluidinto a wellbore through an earthen formation. The fluids of the presentembodiments may have particular application for use in high temperatureenvironments. The fluid formulations disclosed herein may possessrelatively high thermal stability, having particular application for usein environments of approximately 375° F. It is also envisioned that thefluid may be circulated into a well (either pumped through a drillstring during drilling or subsequent to drilling such as by spotting apill of the fluid into the well) and allowed to remain static orsubstantially static for at least 2 days. Thus, during such staticperiods, one or more completion operations may be performed, including,but not limited to placement of a screen, gravel packing, fracking,frac-packing, etc. It more particular embodiments, the fluid may remainstatic in a well for at least 3, 4, 5, 6, 7, or 14 days during (and/orafter) one or more completion operations prior to the well being putinto production. During such time, the invert emulsion fluid of thepresent disclosure may advantageously retain its rheological properties(or at least stay within acceptable rheological properties) over theduration of the time for completion operations to occur (or for the wellto be put into production) and without substantial phase separation.

In any event, the viscosity of the wellbore fluid may be controlledwithin desired ranges, which are in many instances dependent on thegeographic area of activity. The viscosity is a function of plasticviscosity and yield point. As a general rule, as the mud weightincreases, the plastic viscosity increases, but the yield pointincreases by a much smaller magnitude.

Another characteristic is the gel strength of the wellbore fluid. Gelstrength is a characteristic of the wellbore fluid which reflects theability of the fluid to maintain a suspension of additives and drillcuttings, especially when circulation is stopped. As can be appreciated,if circulation of the fluid were terminated, and if all of the suspendedcuttings and additives to the fluid were then permitted to settle to thelowest point, the drill bit and drill string would be literally packedinto a position that would result in severe levels of torque to rotate.Such torque might damage components of the drill string or in someinstances cause the drill string to shear apart. Such a situationresults in loss of the drill bit and sustained periods where positivefootage is not being drilled.

If the fluid gel strength is too low, it may be increased by increasingthe amount of gelling agent incorporated in the fluid. Ideally, thefluid gel strength should be just high enough to suspend barite anddrill cuttings, or other solid particles, when circulation is stopped.However, too high of a gel strength can retard the separation ofcuttings and of entrained gas at the surface, and also because theyraise the pressure to reestablish circulation after changing bits.Furthermore, when pulling pipe, a high gel strength may reduce thepressure of the mud column beneath the bit because of a swabbing action.If the reduction in pressure exceeds the differential pressure betweenthe mud and the formation fluids, the fluids will enter the hole, andpossibly cause a blowout. Similarly, when running pipe into the hole,the downward motion of the pipe causes a pressure surge which may causefracturing with consequent loss of circulation. Methods have beendeveloped for calculation of the magnitude of these pressure surges.

Related to the gel strength control is the ability of the fluid totolerate divalent ions, including the compatibility of the variouscomponents (including polymeric fluid loss control agents and gellingagents) with divalent brines. For example, many products will not resultin the same viscosity profile in divalent brines as compared tomonovalent brines or fresh water. However, in HPHT wells, heavierdivalent brines may be used to balance the pressures downhole. The fluidadditives of this disclosure display a high tolerance to divalentcations, particularly zinc chloride and zinc bromide.

Another function of the fluid is its ability to seal permeableformations exposed by the bit with a low permeability filter cake, forexample. Fluid loss from the borehole may therefore be reduced. In orderfor a filter cake to form, the fluid may contain particles of a sizeslightly smaller than that of the pore openings of the formation. Theseparticles are trapped in the surface pores while finer particles arecarried deeper into the formation. The particles which are deposited onthe formation are known as the filter cake.

The present FLCP may be an invert emulsion having an oleaginouscontinuous phase, a non-oleaginous or aqueous discontinuous phase, andat least one organophilic clay as discussed above. The oleaginous fluidmay be a liquid and more specifically is a natural or synthetic oil andmore particularly the oleaginous fluid is selected from the groupincluding diesel oil; mineral oil; a synthetic oil, such as hydrogenatedand unhydrogenated olefins including poly(alpha-olefins), linear andbranch olefins and the like, polydiorganosiloxanes, siloxanes, ororganosiloxanes, esters of fatty acids, specifically straight chain,branched and cyclical alkyl ethers of fatty acids, mixtures thereof andsimilar compounds known to one of skill in the art; and mixturesthereof. The concentration of the oleaginous fluid should be sufficientso that an invert emulsion forms and may be less than about 99% byvolume of the invert emulsion. In one embodiment, the amount ofoleaginous fluid is from about 20% to about 95% by volume and moreparticularly about 30% to about 90% by volume of the invert emulsionfluid. The oleaginous fluid, in one embodiment, may include at least 5%by volume of a material selected from the group including esters,ethers, acetals, dialkylcarbonates, hydrocarbons, and combinationsthereof.

The aqueous medium, such as an aqueous internal phase of a wellborefluid, of the present disclosure may be water or brine. In thoseembodiments of the disclosure where the aqueous medium is a brine, thebrine is water comprising an inorganic salt or organic salt. The saltmay serve to provide desired density (to balance against the formationpressures), and may also reduce the effect of the base fluid onhydratable clays and shales encountered during drilling. In variousembodiments of the wellbore fluid herein, the brine may includeseawater, aqueous solutions wherein the salt concentration is less thanthat of sea water, or aqueous solutions wherein the salt concentrationis greater than that of sea water. Salts that may be found in seawaterinclude, but are not limited to, sodium, calcium, aluminum, magnesium,potassium, strontium, and lithium, salts of chlorides, bromides,carbonates, iodides, chlorates, bromates, formates, nitrates, oxides,phosphates, sulfates, silicates, and fluorides. Salts that may beincorporated in a brine include any one or more of those present innatural seawater or any other organic or inorganic dissolved salts.

In one embodiment, the brine may be a divalent halide selected from thegroup of alkaline earth halides. The brine may also comprise an organicsalt, such as sodium, potassium, or cesium formate. Inorganic divalentsalts include calcium halides, such as calcium chloride or calciumbromide. Sodium bromide, potassium bromide, or cesium bromide may alsobe used. The salt may be chosen for compatibility reasons, i.e., wherethe reservoir wellbore fluid used a particular brine phase and thecompletion/clean up fluid brine phase is chosen to have the same brinephase. In other embodiments, the divalent halide may be selected fromtransition metal ions including zinc, such as zinc bromide and/or zinccalcium bromide.

The oil/water ratio in invert emulsion fluids conventionally used in thefield is in the range of 65/45 to 85/15. Several factors haveconventionally dictated such ranges, including: the concentration ofsolids in the mud to provide the desired mud weight (solids laden mudsmust have a high O/W ratio to keep the solids oil wet and dispersed) andthe high viscosities often experienced upon increase of the internalaqueous phase (due to the greater concentration of the dispersedinternal phase). However, in addition to such conventional ranges,embodiments of the present disclosure may also relate to invert emulsionfluids having a high internal phase concentration (<50/50 O/W or lessthan 1:1 O/W). Thus in one embodiment the amount of non-oleaginous fluidis more than about 50% by volume, such as from about 50% to about 80% byvolume. In another embodiment, the non-oleaginous fluid is from about60% to about 80% by volume of the invert emulsion fluid. However, giventhat the fluids may also include conventional invert emulsion ratios, inone embodiment, the amount of non-oleaginous fluid ranges from about 1%to about 80% by volume. In another embodiment, the non-oleaginous fluidis preferably from about 5% to about 70% by volume of the invertemulsion fluid. While high internal phase fluids are inherently lessstable, the present fluids, containing a unique combination of clays(discussed above) may unexpectedly have greater stability than a fluidformulated with each clay type alone (without the other) and may allowfor thermal stability of the emulsion over a period of days (which isnecessary when during the later stages of a well such as duringcompletion operations, etc. when a fluid may remain in the well withoutsubstantial shear over at least 3, 4, or 5 days. Thus, one of moreembodiments may involve the use of the present fluids which may possessrheological properties that do not substantially change (that is theystay within the acceptable margins) over the extent of the wellboreoperation.

One embodiment of the present disclosure involves a method of drilling awellbore. In one such illustrative embodiment, the method involvespumping a wellbore fluid into a wellbore during the wellbore through areservoir section of the wellbore, and then allowing filtration of thewellbore fluid into the earthen formation to form a filter cake on thewellbore walls. The filter cake is partially removed afterwards, thusallowing initiation of the production of hydrocarbons from reservoir.The formation of such a filter cake is desired for drilling,particularly in unconsolidated formations with wellbore stabilityproblems and high permeabilities. Further, in particular embodiments,the fluids of the present disclosure may be used to drill the reservoirsection of the well, and the open hole well may be subsequentlycompleted (such as with placement of a screen, gravel packing, etc.)with the filter cake remaining in place. After the completion equipmentis installed, removal of the filter cake may be achieved through use ofa breaker fluid (or internal breaking agent). It is also envisioned thatthe present fluids may be placed in the wellbore (including in thereservoir section of an open hole) as a pill (solids free pill) tocombat against fluid loss. The fluid may also be used during screenand/or liner running or in any other application where a non-Newtonianfluid is used.

As mentioned above, in the drilling of a well, the drilling fluid istypically circulated through the drill string, through the drill bit atthe end of the drill string and up through the annulus between thedrilled wellbore and drill string. The circulated drilling fluid is usedto carry formation rock present as cuttings or drilled solids that areremoved from the wellbore as the drilling fluid is circulated back tothe surface.

In the construction of the well, a casing may be positioned within aportion of the drilled wellbore and cemented into place. The portion ofthe wellbore that is not lined with the casing forms the uncased or openhole section where, in accordance with some embodiments of the presentdisclosure, a sand control screen assembly is placed to facilitategravel packing for controlling the migration and production of formationsand and to stabilize the formation of the open hole section. Once thewellbore is drilled and the casing cemented into place, the well may becompleted by installing sand screens and gravel packing the open holesection so that produced fluids from the formation are allowed to flowthrough the gravel pack and sand screen and may be recovered through thewellbore. The open hole section may be any orientation, includingvertical and horizontal hole sections.

After the open hole and cased hole sections are displaced with therespective displacement fluids, the drilling string may be removed fromthe wellbore and the desired sand control screen assembly may be run orlowered to a selected depth within the open hole section of the wellbore. The sand screen assembly may be run or lowered into the wellboreon a tubular member or wash pipe, which is used for conducting fluidsbetween the sand screen and the surface. Running the sand screenassembly to the selected depth may include positioning the sand screenin vertical or non-vertical (horizontal) sections of the well. A packermay be positioned and set in the casing above the sand screen to isolatethe interval being packed. A crossover service tool may also be providedwith the assembly to selectively allow fluids to flow between theannulus formed by the open hole and the screen assembly and the interiorof the tubular member and wash pipe.

With the sand control screen assembly in place, a gravel pack slurrycontaining gravel for forming the gravel pack and a carrier fluid isintroduced into the wellbore to facilitate gravel packing of the openhole section of wellbore in the annulus surrounding the sand controlscreen. The gravel pack slurry is typically introduced into the tubularmember where it flows to the cross over tool into the annulus of theopen hole section below the packer and the exterior of the sand controlscreen. As the gravel settles within the open hole section surroundingthe screen, the carrier fluid passes through the screen and into theinterior of the tubular member. The carrier fluid is conducted to thecrossover tool and into the annulus between the casing and the tubularmember above the packer.

The invert emulsion fluids may be used with almost any type of liner orand/or sand control screen assembly. These may include pre-holed liners,slotted, liners, wire-wrapped screens, prepacked screens, direct-wrappedsand screens, mesh screens, premium-type screens, etc. Premium-typescreens typically consist of multilayers of mesh woven media along witha drainage layer. Premium-type screens do not have a well defined screenopening size. In contrast, wire wrap screens consist of wire uniformlywrapped around a perforated base pipe. The wire wrap screens have arelatively uniform screen opening defined as gauge opening. Further, asdescribed above, the sand control screen assembly may also include thosewith alternate flow paths or shunt tubes. Moreover, screen assembliesmay also include those that include diverter valves for diverting fluidreturns through a shorter pathway, preventing pressure build up duringthe gravel packing process. Other completion equipment with which theinvert emulsions may be used includes packer assemblies (including swellpacker assemblies), which separate upper annuli from lower productionequipment in a well, or inflow control devices, which limit the inflowof fluids into the production tubing) The particular type of equipmentis of no limitation on the present disclosure; rather, the invertemulsions may be used with any type of equipment while the equipment isbeing run in the hole or during subsequent completion operations priorto the well being put into production. Further, depending on thearrangement, one or more of such completion equipment may be used incombination with each other.

In accordance with embodiments of the present disclosure, prior toinstalling sand control screens (using the present fluids or not) and/orgravel packing (using the present fluids or not), the drilling fluid mayoptionally be first displaced from the open hole section to adisplacement fluid, and a second fluid may optionally be used todisplace the fluid in a cased hole section. Displacement of the drillingfluids from the open hole section may be carried out by introducing thedisplacement fluid into the wellbore by passing the displacement fluidthrough the tubular drill string to the open hole section. As thedisplacement fluid is pumped through the drill string, the drillingfluids in the open hole section are carried upward through the annulusformed by the casing and the drill string. In a particular embodiment,if the formation includes reactive clays, the displacement fluid for theopen hole section may include the present invert emulsions to helpmaintain the integrity of the open hole section containing reactiveshales or clays that could otherwise be damaged if water-based fluidswere used to displace the drilling fluids. In certain embodiments, thevolume of first displacement fluid used may be sufficient to displacethe open hole section plus the cased hole section up to the packersetting depth.

When a sufficient volume of the first displacement fluid is introducedinto the wellbore to displace the drilling fluid from the open holesection of the wellbore, a second displacement fluid (optionally thesame or different than the first) is used to displace at least a portionor all of the cased hole section of the wellbore. In certainembodiments, the volume of the second fluid may be sufficient todisplace the entire cased section above the packer setting depth. Thismay be carried out by raising the end of the tubular drill string sothat it is positioned within the cased hole section above the open holesection so that the second displacement fluid is discharged from the endof the drill string into the cased hole section.

Sand control screens and/or liners, or other completion equipment suchas packer assemblies (including swell packer assemblies) or inflowcontrol devices (limiting the inflow of fluids into the productiontubing) are then run to target depth, which may optionally be in thepresence of the invert emulsions of the present disclosure. The sandcontrol screen may be a standalone sand screen or an expandable sandscreen. After the sand control screen is installed, the well may begravel packed with a invert emulsion fluid, as disclosed herein.Further, one of ordinary skill in the art would appreciate that one ormore of such completion equipment may be used in combination.

According to various embodiments, the fluid formulations of the presentdisclosure may be easily transportable and maintain their propertiesduring transportation. The effectiveness of a wellbore fluid and inparticular the additives found in the wellbore fluid is evaluated bymeasurement of certain characteristics of the wellbore system. Theviscosity, gel strength, filtrate loss, contamination control andtolerance to divalent ion characteristics of wellbore fluids andwellbore systems are all directly attributable to the components of thefluid or mud.

Breaker Fluids

In embodiments described herein, by filtration of a wellbore fluid intothe earthen formation, a filter cake may be formed on the wellborewalls. After completion of the drilling or completion process, thefilter cake may be broken by application of a breaker fluid. The breakerfluid may be circulated in the wellbore during or after the performanceof the at least one completion operation. In other embodiments, thebreaker fluid may be circulated either before, during, or after acompletion operation has commenced to destroy the integrity of and cleanup residual wellbore fluids remaining inside casing or liners. Thebreaker fluid contributes to the degradation and removal of the filtercake deposited on the sidewalls of the wellbore to minimize negativelyimpacting production. Upon cleanup of the well, the well may then beconverted to production.

In one or more embodiments, before, during, or after a completionoperation has started or upon conclusion of all completion operations,the circulation of an acid wash such as hydrochloric acid, sulfuricacid, citric acid, formic acid, acetic acid, other organic acids, ormixtures thereof may be used to at least partially dissolve some of thefilter cake remaining on the wellbore walls. Other embodiments may usebreaker fluids that contain hydrolysable esters of organic acids and/orvarious oxidizers in combination with or in lieu of an acid wash.

Examples of suitable organic acids that may be used as the breakingagent may include salicylic acid, glycolic acid, malic acid, maleicacid, fumaric acid, and homo- or copolymers of lactic acid and glycolicacid as well as compounds containing hydroxy, phenoxy, carboxylic,hydroxycarboxylic or phenoxycarboxylic moieties. In addition to organicacids, hydrolysable esters which may hydrolyze to release an organic (orinorganic) acid may also be used, including, for example, hydrolyzableesters of a C₁ to C₆ carboxylic acid and/or a C₂ to C₃₀ mono- orpoly-alcohol, including alkyl orthoesters. In addition to thesehydrolysable carboxylic esters, hydrolysable phosphonic or sulfonicesters could be utilized, such as, for example, R¹H₂PO₃, R¹R²HPO₃,R¹R²R³PO₃, R¹HSO₃, R¹R²SO₃, R¹H₂PO₄, R¹R²HPO₄, R¹R²R³PO₄, R¹HSO₄, orR¹R²SO₄, where R¹, R², and R³ are C₂ to C₃₀ alkyl-, aryl-, arylalkyl-,or alkylaryl-groups. One example of a suitable hydrolysable ester ofcarboxylic acid is available from M-I, L.L.C. (Houston, Tex.) under thename D-STRUCTOR.

In some instances, it may also be desirable to include an oxidant in thebreaker fluid, to further aid in breaking or degradation of polymericadditives present in a filter cake. Examples of such oxidants mayinclude any one of those oxidative breakers known in the art to reactwith polymers such as polysaccharides to reduce the viscosity ofpolysaccharide-thickened compositions or disrupt filter cakes. Suchcompounds may include peroxides (including peroxide adducts), othercompounds including a peroxy bond such as persulphates, perborates,percarbonates, perphosphates, and persilicates, and other oxidizers suchas hypochlorites, which may optionally be encapsulated as taught by U.S.Pat. No. 6,861,394, which is assigned to the present assignee. Further,use of an oxidant in a breaker fluid, in addition to affecting polymericadditives, may also cause fragmentation of swollen clays, such as thosethat cause bit balling.

It should be appreciated that the amount of delay between the time whena breaker fluid according to the present disclosure is introduced to awell and the time when the fluids have had the desired effect ofbreaking/degrading/dispersing the filter cake may depend on severalvariables. One of skill in the art should appreciate that factors suchas the downhole temperature, concentration of the components in thebreaker fluid, pH, amount of available water, filter cake composition,etc. may all have an impact. For example downhole temperatures can varyconsiderably from 100° F. to over 400° F. depending upon the formationgeology and downhole environment. However, one of skill in the art viatrial and error testing in the lab should easily be able to determineand thus correlate downhole temperature and the time of efficacy of fora given formulation of the breaker fluids disclosed herein. With suchinformation one can predetermine the time period to shut-in a well givena specific downhole temperature and a specific formulation of thebreaker fluid.

However, it should also be appreciated that the breaker fluidformulation itself and thus the fluid's chemical properties may bevaried so as to allow for a desirable and controllable amount of delayprior to the breaking of invert emulsion filter cake for a particularapplication. In one embodiment, the amount of delay for an invertemulsion filter cake to be broken with a water-based displacement fluidaccording to the present disclosure may be greater than 1 hour. Invarious other embodiments, the amount of delay for an invert emulsionfilter cake to be broken with a water-based displacement fluid accordingto the present disclosure may be greater than 3 hours, 5 hours, or 10hours. Thus the formulation of the fluid can be varied to achieve apredetermined break time and downhole temperature.

The superior thermal stability and performance of the formulations ofthis disclosure in controlling the filtrate loss from the wellbore fluidwere determined by conducting the following tests.

Rheology Test

Viscosity is a measurement describing the flow properties of wellborefluids and their behavior while under influence of shear stress. Using aFann 35 Viscometer, Fann 70 Viscometer, Grace Viscometer, therheological parameters, such as plastic viscosity (PV) and yield point(YP) may be determined. One of skill in the art will appreciate that theviscosity measurements will be dependent upon the temperature of the gelcomposition, the type of spindle, and the number of revolutions perminute. Generally, increase in the plastic viscosity and yield pointvalues are proportional to increase of the wellbore fluid density, butthe yield point increases by a smaller magnitude.

Plastic Viscosity Test

Plastic viscosity (PV) is one variable used in the calculation ofviscosity characteristics of a wellbore fluid, measured in centipoise(cP) units. PV is the slope of the shear stress-shear rate plot abovethe yield point and is derived from the 600 rpm reading minus the 300rpm reading. A low PV indicates that the fluid is capable of drillingrapidly because of the low viscosity of fluid exiting at the bit. HighPV may be caused by a viscous base fluid and by excess colloidal solids.To lower PV, a reduction in solids content can be achieved by dilution.

Yield Point Test

Yield point (YP) is another variable used in the calculation ofviscosity characteristics of fluids, measured in pounds per 100 feetsquare (lb/100 ft²). The physical meaning of the Yield Point (YP) is theresistance to initial flow. YP is used to evaluate the ability of afluid to lift cuttings out of the annulus. The Bingham plastic fluidplots a straight line on a shear-rate (x-axis) versus shear stress(y-axis) plot, in which YP is the zero-shear-rate intercept (PV is theslope of the line). YP may be calculated from 300-rpm and 600-rpmviscometer dial readings by subtracting PV from the 300-rpm dial readingand it is reported as lbf/100 ft². A higher YP implies that fluid hasability to carry cuttings better than a fluid of similar density butlower YP.

pH Test

The pH test is performed using pH paper to determine the acidity of thewellbore fluid.

High Temperature High Pressure Fluid Loss Test

“HTHP” is the term used for high temperature high pressure fluid loss,measured in milliliters (mL) according to API bulletin RP 13 B-2, 1990.This test is conducted for testing fluid loss behavior of mud. Mud ispressed through filter paper located in the HTHP filter press at 300° F.with differential pressure at 500 psi for 30 minutes. Thickness offilter cake stuck in filter paper should be less than 2 ml.

Gel Strength Test

The gel strength (thixotropy) is the shear stress measured at low shearrate after a mud has set quiescently for a period of time (10 secondsand 10 minutes in the standard API procedure, although measurementsafter 30 minutes or 16 hours may also be made).

The preparation and the superior properties of the wellbore fluids ofthe present disclosure in a thermally elevated and contaminatedenvironment are further described in the following examples.

The following examples are presented to illustrate the preparation andproperties of the fluids and should not be construed to limit the scopeof the disclosure, unless otherwise expressly indicated in the appendedclaims. All percentages, concentrations, ratios, parts, etc. are byweight unless otherwise noted or apparent from the context of their use.

The wellbore fluids of this disclosure, which include the fluid losscontrol agent and the gelling material comprising a clay and across-linked polymer, effectively control the viscosity, gel strengthand fluid loss of an aqueous wellbore fluid when exposed to hightemperatures.

EXAMPLES

The following examples are provided to further illustrate theapplication and the use of the methods and compositions of the presentdisclosure. The present examples tested different wellbore fluidformulations to assess their potential to be stable at high temperatureswhile providing increased viscosity and gel strength.

Example 1

A sample formulation of fluids as discussed herein may be formulated asa control and formulation 1 with a hectorite clay and a combination ofhigh internal phase emulsifiers. Test data is shown below for suchformulations after 7 days of static aging. After 7 days, phaseseparation was seen to occur in the control and formulation #1.Emulsifier #1 is a reaction product of tall oil with a polyamine, andEmulsifier #2 is a polyolefin amide alkeneamine.

TABLE 1 Wellbore Fluid formulation in zinc bromide/calcium bromidesystem and its rheological properties Formulation Formulation #1 SG ppbbbl/bbl Synthetic IO 16-18 (0.78 SG) 0.78 80.3 0.294 Hectorite clay 1.702 Emulsifier #1 8 Emulsifier #2 2 Internal brine 2.08 500.42 0.686 19.2ppg CaBr2/ZnBr2 2.30 459 Water 1.00 40 Mud weight (target 14.00 ppg)14.0 OWR (%) 40.3/59.7 Base brine density 17.36 Rheology - Static aging(SA) Static aging time (hrs) Initials 600 rpm 195 300 rpm 122 200 rpm 92100 rpm 56 6 rpm 7 3 rpm 4 Gel10 Sec (lbs/100 ft2) 5 Gel10 min Gel10 Sec(lbs/100 ft2) 6 PV (cP) 73 YP (lbs/100 ft2) 49

To fully assess the properties of the formulation, the rheology of theresulting wellbore fluid was measured using a Fann 35 Viscometer at therpm's listed above. At 375° F., each of the wellborefluids was hotrolled (HR) at the time intervals shown or static aged (SA). Inaddition, gel strength (shown as “gels”) was measured at certain secondor minute intervals, the rheology of which was measured with a Fann 35Viscometer set at 3 rpm.

Example 2

A sample formulation of fluids as discussed herein may be formulated asin the above with the addition of magnesium silicate clay, such asGaramite®, and a hectorite clay, such as VERSAGEL HT. Test data is shownbelow for such formulations after 7 days of static aging.

TABLE 2 Wellbore Fluid formulation with hectorite clay and magnesiumsilicate clay in zinc bromide/calcium bromide system and its rheologicalproperties Formulation Formulation #2 ppb bbl/bbl Synthetic IO 16-18(0.78 SG) 80.3 0.294 hectorite clay 1.5 Emulsifier #1 8 Emulsifier #2 2magnesium silicate clay 1.5 Internal brine 500.42 0.686 19.2 ppgCaBr2/ZnBr2 459 Water 40 Mud weight (target 14.00 ppg) 14.0 OWR (%)40.3/59.7 Base brine density 17.36 Rheology - Static aging (10 days at375° F.) Static aging time (days) Initial 10 Rheology Temp 120 F. 120 F.600 rpm 102 230 300 rpm 63 159 200 rpm 49 129 100 rpm 34 90 6 rpm 12 273 rpm 10 22 Gel10 Sec (lbs/100 ft2) 11 18 Gel10 min Gel10 Sec (lbs/100ft2) 14 20 PV (cP) 39 71 YP (lbs/100 ft2) 24 88 ES 42 15

After aging for at least 5 days, formulations #2 exhibited thermalstability in high temperature high pressure (HTHP) conditions,maintained viscosity, and reduced wellbore fluid loss. In addition,formulations #2 exhibited improved low end rheology as compared to thecontrol and formulations #1 shown in Table 1.

Example 3

Additional fluids were formulated as in the above with the presence ofmagnesium silicate clay, such as Garamite®, but with no hectorite clayas in formulations #2 in Table 2. Test data is shown below forformulations #3 after 7 days of static aging. However, the fluids offormulations #3 did not exhibit stability past 5 days.

TABLE 3 Wellbore Fluid formulation with magnesium silicate clay in zincbromide/calcium bromide system and its rheological propertiesFormulation Formulation #3 ppb bbl/bbl Synthetic IO 16-18 (0.78 SG) 80.30.294 Hectorite clay 0 Emulsifier #1 8 Emulsifier #2 2 magnesiumsilicate clay 3 Internal brine 500.42 0.686 19.2 ppg CaBr2/ZnBr2 459Water 40 Mud weight (target 14.00 ppg) 14.0 OWR (%) 40.3/59.7 Base brinedensity 17.36 Rheology - Static aging target 375° F. Static aging time(days) Initial 5 Rheology Temp 120 F. 120 F. 600 rpm 78 Phase 300 rpm 48Separation 200 rpm 36 100 rpm 23 6 rpm 6 3 rpm 5 Gel10 Sec (lbs/100 ft2)6 Gel10 min Gel10 Sec (lbs/100 ft2) 7 PV (cP) 30 0 YP (lbs/100 ft2) 18 0ES 15

Embodiments of the present disclosure provide water-based wellborefluids and methods of wellbore with such fluids for higher temperaturessuch as at least 275° F. The wellbore fluids of the present disclosuremay be stable (over 7 days) in HTHP conditions, maintain viscosity, andprevent wellbore fluid loss at temperatures of at least 275° F., whereasuse of conventional fluid loss control additives may begin to experiencedegradation at lower temperatures. Fluids discussed herein may not causeappreciable levels of formation damage.

Compositions here may relate to solids-free FLCP used with gravel packscreens (i.e., screen running fluids) during open hold gravel packoperations. Since the screens may be easily plugged with solids fromwellbore fluids, solids-free fluids may be used to install such screensto prevent the occurrence of screen plugging.

Although the preceding description has been described herein withreference to particular means, materials, and embodiments, it is notintended to be limited to the particulars disclosed herein; rather, itextends to all functionally equivalent structures, methods, and uses,such as are within the scope of the appended claims.

What is claimed:
 1. A composition comprising: an oleaginous continuousphase; an aqueous discontinuous phase; a first clay comprising anorganophilic smectite clay; and a second clay comprising a magnesiumsilicate clay.
 2. The composition of claim 1, wherein the organophilicsmectite clay comprises a hectorite clay coated with a fatty acid. 3.The composition of claim 1, wherein the magnesium silicate clay is asepiolite and/or palygorskite clay coated with a fatty acid.
 4. Thecomposition of claim 1, wherein the magnesium silicate clay is apre-dispersed clay.
 5. The composition of claim 1, further comprising anemulsifier
 6. The composition of claim 1 wherein the emulsifier is apolyolefin amide alkeneamine.
 7. The composition of claim 1, wherein aratio of the oleaginous phase to the aqueous discontinuous phase is lessthan 1:1.
 8. The composition of claim 1, wherein the composition is asolids-free wellbore fluid.
 9. The composition of claim 1, wherein thecomposition is thermally stable in temperatures up to 375° F.
 10. Thecomposition of claim 1, wherein the composition is thermally stable forat least 5 days.
 11. The composition of claim 1, wherein thediscontinuous phase comprises a halide brine.
 12. The composition ofclaim 11, wherein the halide brine comprises a zinc halide.
 13. Amethod, comprising: circulating an invert emulsion fluid into a wellborethrough a formation, the invert emulsion fluid comprising: an oleaginouscontinuous phase; an aqueous discontinuous phase; a first claycomprising an organophilic smectite clay; and a second clay comprising amagnesium silicate clay.
 14. The method of claim 13, wherein thecirculating comprises spotting the invert emulsion fluid into thewellbore upon experience of fluid loss to the formation.
 15. The methodof claim 13, wherein the circulating comprises circulating the invertemulsion into a reservoir section of the wellbore.
 16. The method ofclaim 13, further comprising: performing at least one completionoperation in the wellbore while the invert emulsion fluid staticallysits within the wellbore for at least 3 days.
 17. The method of claim16, wherein the invert emulsion fluid statically sits withoutsubstantially changing its rheological properties.
 18. The method ofclaim 13, wherein the organophilic clay comprises a hectorite claycoated with a fatty acid.
 19. The method of claim 13, wherein themagnesium silicate clay is an organophilic sepiolite and/or palygorskiteclay.
 20. The method of claim 13, wherein a ratio of the oleaginouscontinuous phase to the aqueous discontinuous phase is less than 1:1.21. The method of claim 13, wherein the invert emulsion fluid is asolids-free wellbore fluid.
 22. The method of claim 13, wherein theinvert emulsion fluid is thermally stable in temperatures up to 375° F.23. The method of claim 13, wherein the invert emulsion fluid isthermally stable for at least 5 days.
 24. The method of claim 13,wherein the fluid further comprises a polyolefin amide alkeneamineemulsifier.
 25. A method comprising: admixing a magnesium silicatedispersed clay and an organophilic smectite clay in an oleaginous basefluid; shearing the dispersed clay and the organophilic clay in theoleaginous base fluid; adding an emulsifier and a halide brine to theoleaginous base fluid to form an invert emulsion fluid; and shearing theinvert emulsion fluid.
 26. The method of claim 25, wherein the shearingthe invert emulsion fluid occurs following additional adding of thehalide brine.